In-well seismic sensor casing coupling using natural forces in wells

ABSTRACT

A mandrel housing for permanently deploying a seismic sensor or sensor apparatus down a well is disclosed. The mandrel is formed integral with or attached to a pipe and is incorporatable into the production piping string. The outer diameter of the mandrel is designed to be slightly smaller than the inside diameter of the well casing which allows the mandrel to naturally come into contact with the well casing at points of deviation, non-linearity, or non-verticality in the casing. This mechanical coupling of the mandrel to the well casing, and hence the earth formation, improves the resolution and type of seismic signals to be detected by the sensor apparatus. The sensor apparatus fits into a groove on the mandrel and is preferably clamped or welded into place or placed within a tunnel formed in the mandrel. The mandrel further preferably contains channels on its side to allow materials within the annulus to flow around the mandrel even when the mandrel is in contact with the casing.

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application is filed concurrently with U.S. PatentApplication having Express Mail No. EL830942248US, Attorney Docket No.13137.0167.NPUS00, entitled “Multiple Component Sensor Mechanism,” U.S.Provisional Patent Application having Express Mail No. EL830942251US,Attorney Docket No. 13137.0131.NPUS00, entitled “Clamp Mechanism forIn-Well Seismic Sensor,” and U.S. Patent Application having Express MailNo. EL830942234US, Attorney Docket No. 13137.0166.NPUS00, entitled“Apparatus and Method or Transporting, Deploying, and Retrieving ArraysHaving Nodes Interconnected by Sections of Cable,” which contain relatedsubject matter and are incorporated herein by reference in theirentireties.

FIELD OF THE INVENTION

[0002] This invention relates generally to seismic sensing, and moreparticularly to seismic surveying of an earth formation in,particularly, a deviated, non-linear, or non-vertical bore hole.

BACKGROUND OF THE INVENTION

[0003] Seismic surveying is a standard tool for the exploration ofhydrocarbon reservoirs. As is known, seismology involves the detectionacoustic waves to determine the strata of geologic features, and hencethe probable location of oil and/or gas.

[0004] Various types of acoustic and/or pressure sensors used inseismology are well known. While seismic sensors can be placed on land,or on the bottom or surface of the ocean, such sensors may also beplaced within the borehole of the well itself. This approach isgenerally known as borehole seismology or vertical seismic profiling(VSP) because the sensors are usually arranged substantially verticallywithin the borehole of the well. Borehole seismology may occur within asingle well, or may be used in multiple wells, i.e., a cross-wellarrangement, as is well known.

[0005] Borehole seismology however is generally somewhat difficult andcostly to perform. According to some prior art borehole seismologyapproaches, sensors are only temporarily located within the borehole.During this temporary placement, the sensors may be used to takereadings, and then must be retrieved from the borehole. While themeasurements are made, production from the well, if any, might need tobe halted, which can be disruptive and costly, particularly ifmeasurements are periodically made to assess strata conditions over agiven time period. Accordingly, because of the time, costs, and hasslesinvolved with temporary displacement of sensors, it is generallypreferred to permanently position the sensors within the borehole, andfurther preferred that such sensing not substantially interfere withnormal production operations.

[0006] Moreover, it is beneficial to mechanically couple certain seismicsensors to the borehole, including displacement sensors, geophones, andaccelerometers, and hence the earth formation of interest. This isbecause the acoustic waves used in seismic analysis will more easilytravel to these sensors without attenuation (coupling through liquids orgases will cause signal attenuation), and because different types ofparticle motion (e.g., shear waves) can be sensed, which is not possiblewhen coupling occurs only through a liquid or gas. However, one must goto some effort to affirmatively couple the sensors to the boreholestructure, usually by active means that can be costly and complex.

[0007] It would be beneficial therefore to deploy a sensor down inborehole in a manner that would naturally (i.e., passively) coupleitself to the borehole, i.e., that would couple without furtherintervention by the production engineer. It would further be beneficialfor such a deployment to be suitable for use within deviated (i.e.,curved, non-vertical, non-straight) wells, as prior art techniques mayexperience problems in dealing with such wells. For example, indeviated, non-linear, or non-vertical wells, sensing apparatuses maystick, break, or become dislodged in such wells.

[0008] The following references, which disclose subject matters to thoserelated herein, may be useful to further understand the technology atissue, and/or its shortcomings, and are hereby incorporated by referencein their entireties: U.S. Pat. Nos. 6,072,567; 6,016,702; 5,361,130;5,401,956; 5,493,390; 5,925,879; 5,767,411; PCT Publication No. WO02/04984.

SUMMARY OF THE INVENTION

[0009] A mandrel housing for permanently deploying a seismic sensor orsensor apparatus down a well is disclosed. The mandrel is formedintegral with or attached to a pipe and is incorporatable into theproduction piping string. The outer diameter of the mandrel is designedto be slightly smaller than the inside diameter of the well casing whichallows the mandrel to naturally come into contact with the well casingat points of deviation, non-linearity, or non-verticality in the casing.This mechanical coupling of the mandrel to the well casing, and hencethe earth formation, improves the resolution and type of seismic signalsto be detected by the sensor apparatus. The sensor apparatus fits into agroove on the mandrel and is preferably clamped or welded into place orplaced within a tunnel formed in the mandrel. The mandrel furtherpreferably contains channels on its side to allow materials within theannulus to flow around the mandrel even when the mandrel is in contactwith the casing.

BRIEF DESCRIPTION OF THE DRAWINGS

[0010] The foregoing and other features and aspects of the presentdisclosure will be best understood with reference to the followingdetailed description of embodiments of the invention, when read inconjunction with the accompanying drawings, wherein:

[0011]FIG. 1 illustrates the placement of production tubing in adeviated well bore.

[0012]FIG. 2 illustrates models to estimate the effects of torque anddrag.

[0013]FIG. 3 illustrates an embodiment of the disclosed mandrel deployedin a well bore and in contact with the well bore casing.

[0014]FIG. 4 illustrates an embodiment of the disclosed mandrel and thesensor apparatus attached to the mandrel.

[0015]FIG. 5 illustrates an exemplary method by which the sensorapparatus can be affixed to the mandrel.

[0016]FIG. 6A illustrates a cross-sectional view of the mandrelembodiment of FIG. 4.

[0017]FIG. 6B illustrates a cross-section view of the mandrel in whichthe production pipe is not concentric with the outside diameter of themandrel.

[0018]FIG. 7 illustrates another exemplary method by which the sensorapparatus can be affixed to the mandrel.

[0019]FIG. 8 illustrates another exemplary method by which the sensorapparatus can be affixed to the mandrel.

[0020]FIG. 9 illustrates a cross-sectional view of an elliptical mandrelembodiment.

[0021]FIG. 10 illustrates another exemplary method by which the sensorapparatus can be affixed to the mandrel using a tunnel.

[0022]FIG. 11 illustrates a cross-sectional view of a mandrel having apolygonal shape.

[0023]FIG. 12 illustrates a cross-section view of a mandrel havingprotrusions.

[0024]FIG. 13 illustrates a displacement device coupled to a productionpipe to facilitate contact between the disclosed mandrel and the casing.

DETAILED DESCRIPTION OF EMBODIMENTS OF THE INVENTION

[0025] In the disclosure that follows, in the interest of clarity, notall features of actual implementations of a seismic sensing mandrel aredescribed in this disclosure. It will of course be appreciated that inthe development of any such actual implementation, as in any suchproject, numerous engineering and design decisions must be made toachieve the developers' specific goals, e.g., compliance with mechanicaland business related constraints, which will vary from oneimplementation to another. While attention must necessarily be paid toproper engineering and design practices for the environment in question,it should be appreciated that the development of a seismic sensingmandrel would nevertheless be a routine undertaking for those of skillin the art given the details provided by this disclosure, even if suchdevelopment efforts are complex and time-consuming.

[0026] The disclosed embodiments are particularly useful in seismicsurveying using deviated wells, such as extended reach wells, andhorizontal well bores, although it will also have application in wellsexhibiting any degree of non-linearity or slant (as most well do) oreven in near-perfectly vertical wells. Deviated, non-linear, ornon-vertical wells present torque or drag related problems duringdrilling because the drill string contacts the low side of the casing ofthe borehole. In the same way, torque and drag phenomenon also occurswith respect to deployment of a production tube. This is shown generallyin FIG. 1, which shows a production tube 1 in contact with a well casing2 at certain contact points 3 as induced by the gravitation influence onthe tube 1 and its amount of flexure within the casing. The casing 2 canbe suitably acoustically coupled to the earth formation or strata in thevicinity of the borehole, especially when, as is typical, the casing iscemented 40 to the borehole 41.

[0027] Contact forces for a cylindrical member such as a production tubeor mandrel can be estimated using well-known torque and drag models. Inthis regard, FIG. 2 shows models for deriving these parameters,including the “soft string” model (top of FIG. 2) and the cantileverbeam model (bottom of FIG. 2). The soft string model involves ananalysis of the effects of torque and normal force on a cylindricalmember under tension. The cantilever beam model involves an analysis ofthe effects of bending of the cylindrical member. An optimal approachfor estimating the true effect of torque and drag can involvecombinations of these two models, as one skilled in the art willrecognize, and the use of such models may facilitate the designing oruse of the mandrel disclosed herein.

[0028] It has been determined that otherwise inadvertent or unwantedcontact between the production tube 1 and the casing 2 can provide asuitable mechanical coupling to allow sensors on the tube to receive andsense seismic signals. FIG. 3 shows such an implementation. In FIG. 3,mandrels 4 which house seismic sensor apparatuses 7 (not shown in FIG.3) are permanently connected to production tubing 1 and become part ofthe production string, which is placed within the deviated bore hole.FIG. 3 shows the mandrels 4 in contact with the well casing 2, which asnoted facilitates seismic sensing by the sensor apparatus 7. Themandrels 4 are designed, as will be explained in further detail later,so that they may be permanently deployed with the production tube 1, andallow seismic images to be procured over a period of time and withoutinterrupting the production of oil/gas from the well. As also will beseen, the mandrels 4 are designed of rigorous construction, thusminimizing the possibility of breaking free from the production tube,and necessitating premature retrieval of the production tube 1.Moreover, the mandrels are designed to passively and naturally come intocontact with the casing, and need not be intentionally or activelyadjusted or oriented to establish such contact as in the prior art. Themandrel design also provides a simpler housing construction for thesensors over more traditional downhole seismic sensing techniques. Whiletwo mandrels 4 are shown in FIG. 3, one or more than two mandrels couldalso be deployed and brought into contact with the casing as will bedescribed herein. In embodiments using fiber-optic-based sensors, therewill preferably be several of the disclosed mandrels which aremultiplexed along one or more fibers to form a seismic array. In anarrayed embodiment, the mandrels 4 are generally spaced at set distanceswithin the well to allow several pick-up points for seismic data alongthe length of the well, thus increasing the extent of the earthformation that can be assessed.

[0029]FIG. 4 illustrates an embodiment of the mandrel 4. As shown, themandrel 4 may comprise or be coupled to pipe ends 20 designed to couplewith the otherwise standard sections of production tubing 1 at threadedmembers 6, although other known methods used to connect pieces ofproduction piping can be used, such as by clamping. A premium threadwith suitably high tensile strength, such as a VAM Ace certifiedthreaded connection having a 233,000-pound minimum tensile capability(based on a VAM Ace Connection), well-known in the art, is suitable.These pipe ends 20 may in turn be similarly connected to the mandrel 4(see for example FIG. 10). Alternatively, the mandrel 4 can slip over anotherwise standard section of production tubing 1, and may be bolted,clamped, welded, or otherwise fused to the tube 1 through any of severalknown standard means. Additionally, the mandrel 4 and associated pipeends 20 may be milled or forged as an integrated unit.

[0030] The inner diameter 5 of the tube contained within the mandrel 4(or the tube or pipe ends to which it is attached or constitutes a partof) is of a size necessary to allow fluids to flow to and from theproduction tubing 1 to which it is coupled and without impedimentthrough the tube. In a preferred embodiment, the inner diameter 5 issubstantially the same as the inner diameter of the otherwise standardsections of production tubing to which it is connected, which can varyfrom well to well as one skilled in the art will understand.

[0031] By contrast, the outer diameter 21 of the mandrel 4 is preferablylarger than the outer diameter of the production tubing 1, but smallerthan the inside diameter of the casing 2 into which it will be deployed.Preferably, the outside diameter 21 should be just smaller than thatinside diameter of the casing 2 to ensure a high probability that themandrel 4 will be brought into contact with the casing 2 at a point ofdeviation, non-linearity, or non-verticality within the well. In thisregard, it is well known that casings within a well are subject tovariation or drift, and accordingly that a particular well can bespecified as having a particular drift diameter indicative of thesmallest extent of the true inside diameter of the casing. It ispreferred that the outside diameter of the disclosed mandrel be ⅛-inchsmaller than the inner diameter of the casing, although other spacingscan be suitable depending on the nature of the well environment inquestion and the degree of deviation, non-linearity, or non-verticalityof the well. Of course, one skilled in the art will recognize that wellscan have a variety of diameters, and accordingly that the disclosedmandrel 4 will take on a variety of different outside diameters inrecognition thereof.

[0032] It is also preferable that the outside diameter 21 be larger thanthe outside diameter of any other structures on or connected to theproduction pipe 1, such as collars, to ensure that the mandrel 4 will bebrought into contact with the casing 2. As it is desired for the mandrel4 to come into contact with the casing 2 at points of deviation,non-linearity, or non-verticality, one skilled in the art willunderstand that the outside diameter 21 of the mandrel will beengineered to function acceptably with a casing 2 inner diameter of agiven value.

[0033] The length L of the mandrel and the degree of curvature of thewell casing at points of deviation, non-linearity, or non-verticalitymust also be considered when engineering the outside diameter 21 of themandrel to ensure that the mandrel will touch, but not become stuck toor damage, the casing 2. A length of approximately 60 inches ispresently preferred for the mandrel 4, although other lengths might besuitable for a given application. However, and as one skilled in the artwill recognize, it may be desirable in a given application to make themandrel 4 as short as possible to minimize any inherent resonances whichmight interference with the seismic measurements to be made. It ispreferred that the mandrel be tapered 25 at its ends to ensure that themandrel can slip through the casing 2 with relative ease withoutbecoming stuck.

[0034] As shown in FIG. 4, the mandrel 4 houses a seismic sensorapparatus 7. The mandrel 4 contains a groove 8 for securely holding thesensor apparatus 7 in place. The groove 8 may be milled from thestarting material from the mandrel 4, may be forged, or formed by manywell-known metal-working means. As shown in FIG. 5, the sensor apparatus7 preferably has a one or more cylindrical housings, and accordingly thegroove 8 preferably has a cylindrical contour. The groove 8 runspreferably along substantially the entire length of the mandrel 4 andallows the sensor to be adjusted within the channel with about a 5-inchplay, which can be beneficial in multi-sensor arrays to adjust therelative spacing between the sensor apparatuses from mandrel to mandrel.

[0035] Many different types of sensor apparatuses may be used inconjunction with the disclosed mandrel 4. In a preferred embodiment, thesensor apparatus 7 constitutes a sensor mechanism, such as disclosed inU.S. Patent Application having Express Mail No. EL830942248US andAttorney Docket No. 13137.0167.NPUS00, which is filed concurrentlyherewith, is entitled “Multiple Component Sensor Mechanism,” and isincorporated herein by reference in its entirety. The sensor mechanismdisclosed in this incorporated application includes a cylindricalhousing for one or more sensors. When a fiber optic based sensor isused, the incorporated sensor mechanism can include one or morecylindrical housings for splice components, fiber organizers, and otherdevices associated with optical fiber. Use of the integrated sensormechanism disclosed in this incorporated application is preferred due tothe benefits provided by its assembly and its small, cylindricalprofile, and due to the fact that the sensor mechanism does not need tobe actively deployed to be brought in contact with the casing, as themandrel 4 passively serves this function.

[0036] Many different types of sensors can be housed in the sensorapparatus 7 of the present invention. Preferably, the sensor constitutesa fiber optic based sensor containing at least one fiber Bragg grating.For example, the sensor apparatus 7 can have one or more accelerometers,such as disclosed in U.S. patent applications Ser. No. 09/410,634, filedOct. 1, 1999 and entitled “Highly Sensitive Accelerometer” and Ser. No.10/068,266, filed Feb. 6, 2002 and entitled “Highly Sensitive Cross AxisAccelerometer,” which are incorporated herein by reference in theirentirety. The accelerometers (not shown) can be positioned in any of thethree axes (x, y, and z) and can transmit respective sensing lightsignals indicative of static and dynamic forces at their location on theoptical fiber. Alternatively, the sensor apparatus 7 can constituteother sensors or sensor systems known in the art for use in a well.

[0037] It should be noted that well-known methods and techniques existin the art for processing signals from sensors placed in a deviated,non-linear, or non-vertical well. For example, the sensor apparatus 7can contain three accelerometers arranged in three orthogonal axes (x,y, and z) or can contain four accelerometers arranged along tetrahedralaxes. When the sensor apparatus 7 is positioned in a deviated,non-linear, or non-vertical well, and assuming the use of athree-orthogonal-accelerometer arrangement, the three axes (x, y, and z)of the sensors will not be oriented to true vertical, and furthermorewill have an unknown rotation. When interpreting the signals, knownmethods and techniques can account for the non-vertical orientation ortilt of the sensors in the well. For example, when the well is drilled,the deviation, non-linearity, or non-verticality can be determinedthrough Measurement While Drilling (MWD) or well-logging techniquesusing, for examples, magnetometers or gyro tools. As is also known,geophysical methods, such as polarization analysis of direct arrivals ofseismic waves emitted from a known source location, can be used toderive the rotated position of the sensors. By knowing tilt androtation, the signals coming form the sensors can be processed oradjusted so that they reflect the true status of the earth formation.

[0038] The sensor apparatus 7 communicates with a cable 11, which ispreferably a fiber optic cable for those instances in which a fiberoptic based sensor apparatus 7 is used, but could also constitute a wireif an electrically based sensor apparatus 7 is used. As shown in FIG. 4,the fiber optic cable 11 emerges from both ends of the sensor apparatus7. Such a dual-ended sensor apparatus 7 allow several sensorsapparatuses to be multiplexed in series, or allows the sensor apparatus7 to be multiplexed with other downhole fiber optic measuring devices,such as pressure sensors, temperature sensors, flow rate sensors ormeters, speed of sound or phase fraction sensors or meters, or otherlike devices. Examples of such auxiliary sensing devices are disclosedin the following U.S. Patent Applications, which are hereby incorporatedby reference in their entireties: Ser. No. 10/115,727, filed Apr. 3,2002, entitled “Flow Rate Measurement Using Short Scale LengthPressures”; Ser. No. 09/344,094, filed Jun. 25, 1999, entitled “FluidParameter Measurement In Pipes Using Acoustic Pressures”; Ser. No.09/519,785, filed Mar. 7, 2000, entitled “Distributed Sound SpeedMeasurements For Multiphase Flow Measurement”; Ser. No. 10/010,183,filed Nov. 7, 2001, entitled “Fluid Density Measurement In Pipes UsingAcoustic Pressures”; and Ser. No. 09/740,760, filed Nov. 29, 2000,entitled “Apparatus For Sensing Fluid In a Pipe.”

[0039] If only one sensor apparatus 7 is used, or for the last sensorapparatus 7 in a string, the fiber optic cable 11 need not proceedthrough both ends but may be single ended. Ultimately, cable 11 proceedsto the surface of the well along the edge of the production pipe 1 to asource/sensing/data collection apparatus as is well known, and which iscapable of interrogating the sensor apparatus 7 and interpreting dataretrieved therefrom.

[0040] The sensor apparatus 7 may be held firmly within the mandrel 4 byseveral means. In a first embodiment shown in FIGS. 4 and 5, the sensorapparatus 7 is held within the mandrel 4 using hinge clamps 9 hinged tothe mandrel 4 using hinge rods 13. The hinge clamps 9 may be rotatedover the sensor apparatus once it is in place and thereafter may bebolted to the mandrel 4 at bolt holes 22 by bolts 10. In a secondembodiment, shown in FIG. 8, clamps 9 are not hinged, but instead arebolted at both ends to the mandrel using bolts 10 as shown. In a thirdembodiment, shown in FIG. 7, clamps 9 may be welded or brazed to themandrel 4 at weld points 23. As it is generally important to protect thesensor apparatus 7 from the harsh downhole environment and to protect itfrom mechanical damage, it is generally preferred that a secure junctionbe made between the clamps 9 and the mandrel 4 such as those disclosedherein, although other like mechanisms may be used. As one skilled inthe art will recognize, and depending on the design of the clamp 9, asingle clamp can be used with a given mandrel 4, or several clamps canbe used as shown. If a single clamp is used, that clamp can be made tospan the entire length of the sensor apparatus 7, which might provideoptimal sensor protection.

[0041] Other structures to secure the sensor apparatus 7 can be used.For example, and as shown in FIG. 10, the sensor can fit within a tunnel17 formed in the side of the mandrel 4. The tunnel 17 is preferablymilled or drilled into the mandrel 4, and preferably has a diameter justslightly larger than the outside diameter of the sensor apparatus 7 suchthat the sensor apparatus 7 slips into but is firmly held by the tunnel17. In such a tunneled embodiment, it is preferably to place seals 18 atthe ends the tunnel 17 to ensure that the sensor apparatus 7 stays inplace when deployed. These seals 18 could be made in any number of waysas one skilled in the art will recognize. For example, they couldcomprise elastomer seals that press fit into the ends of the tunnel 17or screwable seals which mates with threads form on the inside of thetunnel.

[0042] In a preferred embodiment, and referring to the cross-sectionalview of FIG. 6A, channels 12 are formed on the side of the mandrel 4 toallow for the bypass of fluids or gases (and some solids of minimaldimension) that might be located in the annulus between the productionpipe 1 and the casing 2, such as mud, oil/gas, water, or other causticdrilling agents. (These channels 12 can also be seen in the illustrativeembodiments of FIGS. 4 and 5, but are not shown in the other figures forclarity). These channels 12 are preferably milled from the startingmaterial for the mandrel, but may also be forged, stamped, or formed byany other well-known metal-working processes. Although four suchchannels 12 are shown in FIG. 6, more of fewer channels could also beformed, and such channels could be made of differing sizes and shapes.Additionally, the channels 12 need not be parallel, but could forexample be comprised of helical twist grooves, serpentine patterns, etc.

[0043] The tube 5 within the mandrel is preferably concentric with theouter diameter of the mandrel 4, as shown in FIG. 6A, which facilitatesdeployment and retrieval of the mandrel and maximizes the chance thatthe mandrel 4 will not inadvertently become stuck in the casing.However, the mandrel 4 can be positioned such that it is not concentricwith the tube 5, but instead sits off center, as shown in FIG. 6B. Thisorientation allows extra room for the groove 8 or tunnel 17 which housesthe sensor apparatus 7, and, despite the risk of sticking, may helpfacilitate mechanical coupling between the mandrel 4 and the casing 2,because the inner mandrel tube 5 will be inclined, by virtue of itsconnection to the production pipe, to generally center itself within thecasing 2. Such non-concentric embodiments may cause a minor degree offlexure in the production pipe, which may not be desirable in someapplications and environments.

[0044] Other variations in the topology of the mandrel 4 are possible toallow for the flow of fluid around the mandrel in the annulus. Forexample, and referring to FIG. 9, an elliptical shape is provided forthe outside surface of the mandrel 4. As with the other embodimentsdisclosed herein, the maximum diameter of the ellipse is preferably aslarge as possible, e.g., ⅛ inch short of the inner diameter of thecasing, but still small enough to pass through the casing 2. The minimumdiameter defines a channel 12 allowing for the passage of fluids orother materials in the annulus.

[0045] The mandrel 4 is preferably as stiff as possible to ensure goodacoustic coupling between the seismic events to be detected and thesensor apparatus 7, but can be comprised of any number of materialstypically used for downhole tools. High strength, anti-corrosivematerials, such as stainless steel, are suitable. Construction of themandrel using such materials, and using a 5.5-inch diameter mandrel,will result in a mandrel component weighing about 150-200 pounds. Ofcourse, the design of mandrel 4 is preferably modified depending on theenvironment (well) in which it is to be placed, which can vary from wellto well in terms of their pressures, temperatures, and exposure tocaustic chemicals. The material of the mandrel 4 may need to be modifiedif sufficient amounts of hydrogen sulfide, or “sour gas,” are present,and such sour gas resistant metallurgies are well known to those ofskill in the art. Additionally, stabilizing or stiffening structurescould also be included within the mandrel body.

[0046] As discussed, it is preferable when making seismic measurementsfor the disclosed mandrel to touch, i.e., mechanically couple to, thecasing and hence the earth formation under analysis. It is preferablethat the mandrel not rock, sway, or torque within the casing, which itmight be prone to do given the turbulent nature of the downholeenvironment. In this regard, other shapes for the mandrel might beemployed to improve coupling and to maximize the probability of holdingthe mandrel steady during the receipt of seismic measurements. (Theabove-disclosed “round” mandrels, while believed suitable for some ormost applications, might function less well in such turbulentenvironments.)

[0047] Accordingly, for those applications requiring firmer mechanicalcoupling, the design of the mandrel could be changed. One example ofsuch a change is shown in FIG. 11, which shows a mandrel 4 that istriangular in cross section. As shown in that Figure, when the mandrel 4touches the casing 2, it will touch at the outer points 31 of thetriangular cross section. Because, as in the other embodiments, theouter diameter of the triangle (were it circumscribed in a circle) isjust smaller than the inner diameter of the casing, e.g., by ⅛ inch,chances are improved that the mandrel 4 will touch the casing 2 at twopoints 31 at a given cross section, i.e., at two points of the triangle,as shown in FIG. 11. (By contrast, a circular mandrel will only touchthe casing at one point at a given cross section). Touching the casingat two points 31 will tend to prevent the mandrel 4 from torquing orrolling with respect to the casing 2, and hence may help in a givenapplication to hold the mandrel steadier with respect to the casing whencompared with round mandrel embodiments. Of course, other crosssectional shapes may achieve these same beneficial results, such assquares, hexagons, etc., and these shapes may also be beneficial in thatthey might add mechanical stability or stiffness to the mandrel.Furthermore, such shapes will naturally form channels 12 with respect tothe side of the casing to allow for the flow of materials past themandrel in the annulus. Such alternative polygonal cross sections neednot be formed of straight lines, but could be bowed, as represented bydotted line 28 in FIG. 11 (which might require the positions of theinner pipe and sensor apparatus 7 to be adjusted within the mandrel).

[0048] The foregoing benefits of these alternative polygonal embodimentscan also effectively be realized using an otherwise round mandrel. Forexample, in FIG. 12, there is disclosed a mandrel 4 that is otherwisesimilar to the rounded embodiments disclosed in FIGS. 4-10, but includesprotrusions 30. The protrusions 30 project radially from the mandrel 4and are designed to contact the casing 2 in much the same way that thepolygonal embodiments of FIG. 11 would, i.e., preferably at two pointsof contact. The protrusions 30 define, in FIG. 12, a hexagon, but otherpolygonal shapes are possible. The protrusions preferably run along theentire length of the mandrel 4, but may also appear at certain pointsalong it length, or only at the top and bottom of the mandrel where theyare most likely to touch. Although not shown, the protrusions 30 may betapered to reduce the possibility of catching on the casing 2 as themandrel is deployed downhole. The protrusions 30 can be milled from thebody material for the mandrel, or may be attached by any well-knownmetal-working techniques, such as brazing, bolting, clamping, etc. Aswith the other embodiments, the outer diameter of the protrusions (werethey circumscribed in a circle) are preferably just smaller than theinner diameter of the casing to improve the chances of mechanicalcoupling to the casing. The protrusions may constitute many differentshapes suitable for coupling with the casing, such as rounded bumps, andmay comprise different heights or thicknesses.

[0049] The foregoing thus discloses a seismic sensing mandrelconstructed of minimal parts, and which is of a suitably solidconstruction to house and protect the preferred fiber optic sensorsdisclosed herein. However, the mandrel 4 is also easily adapted to housemore traditional seismic sensors, such as those that are electricallyand/or mechanically based. The mandrel is also easily adaptable to houseother such structures or their cabling. For example, additional channelsor tunnels could be formed in the mandrel 4 to allow for the passage ofadditional electric or fiber optic cables. As disclosed, the mandrelmeets or exceeds strength requirements for production tubing.

[0050]FIG. 13 discloses a design for bringing the mandrel 4 into contactwith the casing 2, again using natural forces. In FIG. 13, adisplacement device 35 is shown connected to the production pipe nearthe mandrel. The displacement device 35 is designed to displace theproduction pipe from its natural center within the casing, andaccordingly has a radius D₂ which is preferably just larger than theaverage distance D₁ between the outside diameter of the production pipe1 and the inside diameter of the casing 2. The displacement device willgenerally touch the casing 2 throughout its entire length as theproduction pipe 1 and the mandrel 4 are deployed. To reduce the chanceof catching during deployment, the displacement device 35 may be taperedas shown. By displacing the production pipe 1, the mandrel 3 is likewisedisplaced within the casing 2, improving the chance of mechanicallycoupling the mandrel to the casing. Because the production pipe 1 issomewhat flexible, both the mandrel 3 and the displacement device 35should be able to slip through the casing 2 without issue, with areas offriction or undesirable narrowness in the casing 2 being relieved byslight bending of the production pipe 1. To ensure that the pipe 1 isnot overstressed or bent to the point of fracture, it may be desirableto place the displacement device 35 at a suitable distance from themandrel 3. To further reduce such unwanted stresses on the productionequipment, it may be necessary in some applications to design thedisplacement device 35 and the mandrel in highly tapered configurationsto reduce the chances of catching on the casing. It should be noted thatthis embodiment may generally cause the mandrel 3 to contact the casingeven in locations where the casing is perfectly vertical, and henceimproves the ability of the disclosed mandrel to take sensor measurementeven in non-deviated wells or wells of only slight deviation,non-linearity, or non-verticality. The displacement device may comprisemany known structures, but in a preferred embodiment comprises a solidblock or fin of steel bolted to the production pipe. Other structures 35capable of displacing the production tube 1 and/or the mandrel 4 andmethods for affixing such structures to the pipe 1 are well within thepurview of those skilled in the art. Although shown above the mandrel 4on the production pipe, the displacement device 35 will serve the samefunction if mounted below the mandrel 4 on the pipe 1. If multiplemandrels on used on a given production tube, multiple displacementdevices 35 may be used as well.

[0051] While particularly useful for the deployment of sensors usablefor vertical seismic analysis, the disclosed mandrel will have utilityfor the deployment of other types of sensors as well, such as pressureand temperature sensors. Additionally, while the disclosed mandrel isparticularly useful in deviated, non-linear, or non-vertical wells, itcan have utility for the deployment of other sensors that needmechanical rigidity but that would not necessarily benefit from contactor mechanical coupling with the well casing.

[0052] The term “outside diameter” as it applies to the mandrel shouldbe understood as referring to the outside diameter of a circle thatcircumscribes the mandrel and its accompanying structures if any.Accordingly, all of the disclosed embodiments disclosed herein, be theycircular or not, and including those of polygonal cross section orhaving protrusions extending from the body of the mandrel, should beunderstood as having an “outside diameter.” Contacting the mandrel tothe well by “natural force” denotes contact between the mandrel and thecasing without active actuation of any devices capable of facilitatingsuch contact and without active intervention on the part of theproduction engineer.

What is claimed is:
 1. An apparatus deployable down a well having a casing with an inner diameter, comprising: a mandrel containing a first tube coupleable to a production tube, the mandrel having an outside diameter; and at least one fiber-optic-based seismic sensor housed within the mandrel.
 2. The apparatus of claim 1, wherein the mandrel is round in cross section.
 3. The apparatus of claim 1, wherein the mandrel is polygonal in cross section.
 4. The apparatus of claim 1, wherein the mandrel contains a plurality of protrusions extending radially from the mandrel.
 5. The apparatus of claim 1, wherein the sensor is housed within a groove formed in an outside surface of the mandrel.
 6. The apparatus of claim 5, further comprising a means for holding the sensor within the groove.
 7. The apparatus of claim 1, wherein the sensor is housed within a tunnel formed within the mandrel.
 8. The apparatus of claim 1, wherein the mandrel contains a plurality of channels.
 9. The apparatus of claim 1, wherein the sensor comprises three seismic sensors oriented orthogonally with respect to each other.
 10. The apparatus of claim 1, wherein the first tube is not concentric within the mandrel.
 11. The apparatus of claim 1, wherein the outside diameter of the mandrel is slightly less than that of the inner diameter of the casing.
 12. The apparatus of claim 1, further comprising a production tube coupled to the first tube, and further comprising a displacement device coupled to the production tube.
 13. The apparatus of claim 1, further comprising at least one channel formed on an outside surface of the mandrel to allow the passage of materials between the mandrel and the casing.
 14. An apparatus deployable down a well having a casing with an inner diameter, comprising: a mandrel containing a tube coupleable to a production tube, the mandrel having an outside diameter slightly less than that of the inner diameter of the casing such that the mandrel is capable of directly contacting the casing by natural forces; and at least one sensor housed within the mandrel.
 15. The apparatus of claim 14, wherein the mandrel is round in cross section.
 16. The apparatus of claim 14, wherein the mandrel is polygonal in cross section.
 17. The apparatus of claim 14, wherein the mandrel contains a plurality of protrusions extending radially from the mandrel.
 18. The apparatus of claim 14, wherein the sensor is housed within a groove formed in an outside surface of the mandrel.
 19. The apparatus of claim 18, further comprising a means for holding the sensor within the groove.
 20. The apparatus of claim 14, wherein the sensor is housed within a tunnel formed within the mandrel.
 21. The apparatus of claim 14, wherein the at least one sensor comprises at least one seismic sensor.
 22. The apparatus of claim 21, wherein there are three seismic sensors oriented orthogonally with respect to each other.
 23. The apparatus of claim 14, wherein the first tube is not concentric within the mandrel.
 24. The apparatus of claim 14, further comprising at least one channel formed on an outside surface of the mandrel to allow the passage of materials between the mandrel and the casing.
 25. The apparatus of claim 14, further comprising a production tube coupled to the first tube, and further comprising a displacement device coupled to the production tube.
 26. The apparatus of claim 14, wherein the sensor comprises an optical sensor.
 27. An apparatus deployable down a well having a casing with an inner diameter, comprising: a mandrel containing a first tube coupleable to a production tube, the mandrel having an outside diameter; and at least one sensor housed within a groove in the mandrel, wherein the first tube is not concentric within the mandrel.
 28. The apparatus of claim 27, wherein the mandrel is round in cross section.
 29. The apparatus of claim 27, wherein the mandrel is polygonal in cross section.
 30. The apparatus of claim 27, wherein the mandrel contains a plurality of protrusions extending radially from the mandrel.
 31. The apparatus of claim 27, wherein the sensor is housed within a groove formed in an outside surface of the mandrel.
 32. The apparatus of claim 31, further comprising a means for holding the sensor within the groove.
 33. The apparatus of claim 27, wherein the sensor is housed within a tunnel formed within the mandrel.
 34. The apparatus of claim 27, wherein the at least one sensor comprises at least one seismic sensor.
 35. The apparatus of claim 34, wherein there are three seismic sensors oriented orthogonally with respect to each other.
 36. The apparatus of claim 27, further comprising at least one channel formed on an outside surface of the mandrel to allow the passage of materials between the mandrel and the casing.
 37. The apparatus of claim 27, wherein the outside diameter of the mandrel is slightly less than that of the inner diameter of the casing.
 38. The apparatus of claim 27, further comprising a production tube coupled to the first tube, and further comprising a displacement device coupled to the production tube.
 39. The apparatus of claim 27, wherein the sensor comprises an optical sensor.
 40. A system for taking measurements in a well, comprising: a well comprising a casing having an inner diameter; a production tube disposed in the well; at least one mandrel coupled to the production tube, the mandrel having an outside diameter; and at least one sensor apparatus housed within the mandrel, wherein the mandrel is in contact with the casing.
 41. The system of claim 40, wherein the mandrel is round in cross section.
 42. The system of claim 40, wherein the mandrel is polygonal in cross section.
 43. The system of claim 40, wherein the mandrel contains a plurality of protrusions extending radially from the mandrel.
 44. The system of claim 40, wherein the sensor is housed within a groove formed in an outside surface of the mandrel.
 45. The system of claim 44, further comprising a means for holding the sensor within the groove.
 46. The system of claim 40, wherein the sensor is housed within a tunnel formed within the mandrel.
 47. The system of claim 40, wherein the at least one sensor comprises at least one seismic sensor.
 48. The system of claim 47, wherein there are three seismic sensors oriented orthogonally with respect to each other.
 49. The system of claim 40, further comprising at least one channel formed on an outside surface of the mandrel to allow the passage of materials between the mandrel and the casing.
 50. The system of claim 40, wherein the outside diameter of the mandrel is slightly less than that of the inner diameter of the casing.
 51. The system of claim 40, wherein the mandrel contains a first tube coupled to the production tube, and wherein the first tube is not concentric within the mandrel.
 52. The system of claim 40, further comprising a displacement device coupled to the production tube.
 53. The system of claim 52, wherein the displacement device has a radial protrusion away from an axis of the production tube which is larger than the difference between one-half of the inside diameter of the casing and one-half the outside diameter of the production tube.
 54. The system of claim 52, wherein the displacement device touches the casing to displace the production device from the axis of the casing.
 55. The system of claim 40, wherein the sensor comprises an optical sensor.
 56. The system of claim 40, wherein the well is deviated, non-linear, or non-vertical.
 57. The system of claim 56, wherein the mandrel is in contact with the casing at a point of deviation, non-linearity, or non-verticality in the well.
 58. A method for deploying an apparatus capable of taking seismic measurements, comprising: deploying a production tube down a well containing a casing with an inner diameter, wherein the production tube comprises at least one mandrel with an outside diameter which houses at least one sensor; and contacting the mandrel and the casing by natural forces.
 59. The method of claim 58, wherein the mandrel is round in cross section.
 60. The method of claim 58, wherein the mandrel is polygonal in cross section.
 61. The method of claim 58, wherein the mandrel contains a plurality of protrusions extending radially from the mandrel.
 62. The method of claim 58, wherein the sensor is housed within a groove formed in an outside surface of the mandrel.
 63. The method of claim 62, further comprising a means for holding the sensor within the groove.
 64. The method of claim 58, wherein the sensor is housed within a tunnel formed within the mandrel.
 65. The method of claim 58, wherein the at least one sensor comprises at least one seismic sensor.
 66. The method of claim 65, wherein there are three seismic sensors oriented orthogonally with respect to each other.
 67. The method of claim 58, wherein the mandrel further comprising at least one channel formed on an outside surface of the mandrel to allow the passage of materials between the mandrel and the casing.
 68. The method of claim 58, wherein the outside diameter of the mandrel is slightly less than that of the inner diameter of the casing.
 69. The method of claim 58, wherein the mandrel contains a first tube coupled to the production tube, and wherein the first tube is not concentric within the mandrel.
 70. The method of claim 58, wherein contacting the mandrel and the casing by natural forces comprises the use of a displacement device coupled to the production tube.
 71. The method of claim 70, wherein the displacement device has a radial protrusion away from an axis of the production tube which is larger than the difference between one-half of the inside diameter of the casing and one-half the outside diameter of the production tube.
 72. The method of claim 70, wherein the displacement device touches the casing to displace the production device from the axis of the casing.
 73. The method of claim 58, wherein the sensor comprises an optical sensor.
 74. The method of claim 58, wherein the well is deviated, non-linear, or non-vertical.
 75. The method of claim 58, wherein contacting the mandrel and the casing by natural forces comprises contact between the mandrel and the casing at a point of deviation in the well. 